The present invention is directed to an apparatus and method for use in downhole pressure information gathering to determine condition of the reservoir and potential of a given well as a stimulation candidate.
Historically, because of the high cost of stimulation treatments, it has been, and continues to be, critical to select proper candidate wells on which to perform stimulation treatments. Three important pieces of data used in determining if a well is a candidate for a stimulation treatment are (1) the extent of the reservoir, i.e., how much oil is in place accessible from the well bore; (2) the existence of damage in the near well bore region; and (3) measurement of portability. If the well bore has penetrated only a very small reservoir, the total recovery that may be had from that reservoir may not be enough to justify the cost of an expensive stimulation treatment. Further, if there is no near well bore damage or extremely tight permeability, a stimulation treatment may be ineffective in increasing production to an economical production. One other important consideration before determining if a well is a candidate for a stimulation treatment is to determine if the well is in good mechanical condition. This is important for three reasons: (1) to ensure that the well will last long enough to take advantage of the increased production; (2) to ensure that the stimulation treatment will go where it is intended to go; and (3) to ensure that no damage or danger will occur below ground level.
The present invention offers an improved apparatus and method for measuring downhole flowing and shut-in pressures, as well as for performing mechanical integrity analysis. The same type of analysis has been done in the past, but with much less efficiency and at a higher expense and risk to production.
In the past, in flowing wells, pressure analysis has been performed by using a wireline-conveyed, downhole pressure gauge, in conjunction with a wireline-conveyed shut-in tool to control fluid flow. The first initial problem with such a system is that with the use of wireline, a lubricator stack tall enough to receive the entire tool string is required to ensure proper well control at all times. In addition, with a shut-in pressure analysis, it is important for accurate test results that the well be shut-in at a time when the well has reached a stable flow.
In a flowing well, particularly a gas well, high pressures and high flow rates may make it virtually impossible to get a wireline tool down the tubing string without first having to kill the well. Once the well is killed, only then can the operator run in the hole with a wireline shut-in tool and pressure gauge. Once the downhole tool is seated in a landing nipple below the packer, the kill fluid can be circulated out and the downhole shut-in valve can be opened to allow free flow of the fluids into the well bore. Once flow is started again, it will require some period of time to get back to a stable flow region, generally at least 72 hours, but for truly accurate results it should be the amount of time that the well had flowed prior to shut-in. At that point in time, the shut-in valve is closed and the pressure build-up test is begun.
After the pressure build-up test, it will once again generally be necessary to circulate kill fluid into the hole for well control while the shut-in wireline tool is removed. After the wireline tool is removed, the kill fluid can be circulated out of the hole and the well can then be put back on production.
The obvious problems with past wireline systems are that the operator will be losing production any time the well is shut-down or killed. In addition, particularly in a gas well, there is always a risk that once a well is killed it may not be able to kick off or re-start production again. Therefore, an improved apparatus and method are needed to perform downhole testing while requiring less down-time of the well, less risk of production stoppage due to killing the well, and quicker and easier operations.
While pressure gauges have been run in the past using coiled tubing with wireline inside, those applications have generally been in horizontal wells or wells with doglegs. In horizontal or doglegged wells, the rigidity of the coiled tubing may be necessary to push the logging tool to the desired depth or location. However, such a system has not been used in conjunction with a downhole shut-in valve such that the effects of wellbore storage on the pressure build-up test can be greatly reduced. Also, the use of coiled tubing systems in horizontal wells in the past has generally been at static conditions, i.e., with the hole full of mud or water, not during flowing conditions as under the present invention.
In addition, no mechanical integrity testing can be performed without a downhole shut-in tool. As a result, use of a coiled tubing system without a downhole shut-in tool will still require that once the build-up work is complete, a wireline downhole shut-in tool be run in the hole to test the mechanical integrity of the tubing and/or casing string. At that point, the same problems will be encountered with high pressure/high flow rate wells in that the well may have to be killed just to get the shut-in tool in the hole to perform the mechanical integrity test. While killing the well after the pressure testing is complete eliminates some of the inherent problems of wireline testing, the risk of the well not returning to full production still exists anytime a well is killed.